In a conventional fossil fuel-fired (e.g., coal-fired) power generating unit, a fossil fuel/air mixture is ignited in a boiler. Large volumes of water are pumped through tubes inside the boiler, and the intense heat from the burning fuel turns the water in the boiler tubes into high-pressure steam. In an electric power generating application, the high-pressure steam from the boiler passes into a turbine comprised of a plurality of turbine blades. Once the steam hits the turbine blades, it causes the turbine to spin rapidly. The spinning turbine causes a shaft to turn inside a generator, creating an electric potential.
As used herein, the term “power generating plant” refers to one or more power generating units. Each power generating unit drives one or more turbines used for generating electricity. A power generating unit is typically powered by fossil fuels (including but not limited to, coal, natural gas or oil), and includes a boiler for producing high temperature steam; air pollution control (APC) devices for removal of pollutants from flue gas; a stack for release of flue gas; and a water cooling system for condensing the high temperature steam. A typical power generating unit will be described in detail below.
Boiler combustion or other characteristics of a fossil fuel-fired power generating unit are influenced by dynamically varying parameters of the power generating unit, including, but not limited to, air-to-fuel ratios, operating conditions, boiler configuration, slag/soot deposits, load profile, fuel quality and ambient conditions. Changes to the business and regulatory environments have increased the importance of dynamic factors such as fuel variations, performance criteria, emissions control, operating flexibility and market driven objectives (e.g., fuel prices, cost of emissions credits, cost of electricity, etc.).
Over the past decade, combustion optimization systems have been implemented for advanced control of the combustion process within the furnace. Typically, combustion optimization systems interface with a distributed control system (DCS) of a power generating unit. Based upon the current operating conditions of the power generating unit, as well as a set of operator specified goals and constraints, the combustion optimization system is used to compute the optimal fuel-to-air staging within the furnace to achieve the desire goals and constraints.
Combustion optimization systems were originally implemented to reduce nitrogen oxides (NOx) produced in the furnace and emitted to the atmosphere via the stack. U.S. Pat. No. 5,280,756 to Labbe et al. (issued Jan. 25, 1994) teaches a method and system for controlling and providing guidance in reducing NOx emissions based upon controllable combustion parameters and model calculations while maintaining satisfactory plant performance. U.S. Pat. No. 5,386,373 to Keeler et al. (issued Jan. 31, 1995) teaches the use of a predictive model of emissions including NOx in conjunction with a control system. U.S. Pat. No. 6,381,504 to Havener et al. (issued Apr. 30, 2002) describes a method for optimally determining the distribution of air and fuel within a boiler by aggregating the distributions of air and fuel into two common variables, performing an optimization, and then computing the optimal distribution of fuel and air based upon the optimal values of the aggregated variables. U.S. Pat. No. 6,712,604 issued to Havlena (issued Mar. 30, 2004) describes a system for controlling the combustion of fuel and air in a boiler such that the distributions of NOx and CO are maintained to average less than the maximum permitted levels.
Recently, combustion optimization approaches have been used to control boiler parameters in addition to NOx, including unit heat rate, boiler efficiency, and mercury emissions. U.S. patent application Ser. No. 10/985,705 (filed Nov. 10, 2004) entitled “System for Optimizing a Combustion Heating Process” (fully incorporated herein by reference) teaches an approach to modeling controllable losses in a power generating unit and a method for optimizing the combustion process based upon these controllable losses. U.S. patent application Ser. No. 11/301,034 (filed Dec. 12, 2005) entitled “Model Based Control and Estimation of Mercury Emissions” (fully incorporated herein by reference) teaches a system and method for reducing mercury emissions from a coal-fired power plant while observing limits on the amount of carbon in the fly ash produced by the combustion process.
The combustion optimization approaches described above provide high level control of the boiler similar to that performed by the operator. The combustion optimization system relies upon the Distributed Computer System (DCS) to execute its commands. For example, the DCS is typically used to control the level of oxygen in the furnace, the position of air flow dampers, and the amount of fuel entering the power generating unit. It is assumed that the DCS, typically using a design of cascading and interacting proportional, integral and derivative (PID) control, provides a sufficiently accurate and fast control of the basic control loops in the boiler. Thus, the combustion optimization system is used to compute the optimal setpoints for the boiler and the DCS is used to provide accurate and fast control of the basic loops to these setpoints.
Although the DCS is typically capable of providing adequate regulatory control of the power generating unit, there are a significant number of situations where a DCS based control scheme is not sufficient for maintaining the appropriate operating conditions in the boiler. For example, large variations in the heat content of the fuel and inaccurate oxygen sensor readings can lead to flame extinction of burners using typical DCS control schemes. If large fuel variations or inaccurate oxygen readings are known to exist, operators are required to either manually control the boiler or use artificially high levels of oxygen to prevent flame extinction. Either method leads to sub-optimal performance of the boiler.
Variations in heat content of the fuel can lead to flame extinction or flame instability of burners due to inadequate air flow. Specifically, as the heat content of the fuel changes, the method in which air is injected into the boiler varies. Two streams of air (i.e., primary air and secondary air) are used for injecting air into the boiler. (For ease of explanation in this background section, a boiler without overfire air is considered.) The primary air is used to transport coal to the burners. The secondary air is used to provide excess oxygen (i.e., oxygen introduced into the boiler above that required for full combustion of the fuel) and to swirl around the primary air and fuel inside the burner. The flow of secondary air around the primary air is critical to maintaining proper flame and combustion characteristics in the boiler. The total amount of both primary air and secondary air injected into the boiler is determined by load demand and the required oxygen at the exit of the furnace.
As the heat content of the fuel varies, the amount of primary air needed to transport the fuel to a burner changes. If the heat content drops, more fuel is needed, and consequently more primary air is needed to transport the fuel. Therefore, a lower rank fuel requires more primary air than a higher rank fuel. Since the overall amount of total air typically injected into the boiler stays approximately constant at a fixed load, the secondary air that is injected into the burner varies as the primary air varies to maintain constant total air. As the heat content of the fuel decreases, primary air increases resulting in a decrease in secondary air. At some point, if the heat content falls too low, flame extinction of the burner becomes highly probable due to the lack of sufficient secondary air. Because it is difficult and expensive to instantaneously determine the heat content of the fuel using sensors, it is difficult to create an algorithm to recognize this situation in the DCS using commonly available logic and control schemes. Therefore, current DCS logic and control schemes can lead to the high probability of flame extinction if the heat content of the fuel is significantly lower than expected.
A second cause of flame instability or extinction is inaccurate oxygen measurements in the boiler. In this regard, one or more oxygen sensors are located in the furnace where combustion is complete to measure oxygen concentration in the flue gas. It should be appreciated that the measured oxygen concentration is also indicative of “excess oxygen” since a percentage value for excess oxygen can be determined from the measured oxygen concentration. If the oxygen sensors produce a higher than actual reading of oxygen concentration (indicative of higher levels of excess oxygen), the DCS will be forced to lower secondary air to the boiler. Once again, if the secondary air falls too low, flame extinction becomes highly probable. Therefore, an artificially high reading of oxygen from the sensors in the furnace can lead to flame extinction using current DCS control schemes.
To avoid these problems, prior to the invention disclosed herein, operators of power generating units have had two options:                1) Manual Control: The operator directly controls the secondary air rather than using a PID control loop for maintaining the level of oxygen in the furnace. Using this approach, the operator must constantly monitor a variety of boiler operating conditions such as the excess oxygen in the furnace, the fuel entering the furnace, and the amount of secondary air. If the secondary air becomes too low to maintain proper flame stability, due either to low heat content of the fuel or drift in the oxygen sensors or a combination of these factors, the operator must manually increase the amount of secondary air to prevent flame extinction. (This subsequently increases the oxygen in the boiler.) This approach requires constant operator attention to prevent flame extinction. Because it is difficult to maintain constant attention, many operators choose the second option which is described hereinafter.        2) Artificially High Setpoint for Oxygen: A second approach to prevent flame extinction, due either to low heat content of the fuel or drift in the oxygen sensors or a combination of both, is to use an artificially high setpoint for oxygen in the furnace. Using this approach, the operator sets the oxygen at a level such that under any circumstances the secondary air will be sufficient to prevent flame extinction. Although this approach is simple and can be implemented by current DCS systems, it has serious drawbacks. High levels of oxygen in the boiler lead to formation of high levels of nitrogen oxides (NOx) in the boiler. Because NOx is a major regulated air pollutant, this approach leads to unwanted and unnecessary air pollution. In addition, an increase in the oxygen also leads to a decrease in overall efficiency of the boiler. Therefore, setting an artificially high value for oxygen does prevent flame extinction and is possible using current DCS control schemes; however, it leads to excess air pollution and a reduction in overall power generating unit efficiency.        
The existing solutions to the foregoing problems are not suitable for use with a combustion optimization system. In this regard, to properly implement a combustion optimization system all critical control loops, such as oxygen, must be under automatic control. Therefore, the first approach, which relies on manual control of excess oxygen, cannot be used in conjunction with a combustion optimization system. The second approach may be used in conjunction with a combustion optimization system but places an artificially high constraint on the lower level of oxygen in the boiler. Since most combustion optimization systems are installed to improve heat rate or decrease NOx, lowering excess oxygen in the boiler below this artificially high constraint is critical to the success of such systems. Therefore, an alternative approach for control of excess oxygen is needed. This alternative approach would have significant environmental and economic benefits whether it is used in conjunction with a combustion optimization system or used without such a system.
The present invention provides a system that overcomes the abovementioned drawbacks of the prior art, and provides advantages over prior art approaches to control and optimization of power generating units.